U.S. patent application number 12/388994 was filed with the patent office on 2009-08-20 for production and delivery of a fluid mixture to an annular volume of a wellbore.
This patent application is currently assigned to Chevron U.S.A. Inc.. Invention is credited to Ronald Gene Bland, James B. Bloys, Robert B. Carpenter, John M. Daniel, Ron Lee Foley, Manuel E. Gonzalez, Robert E. Hermes, Ian M. Robinson.
Application Number | 20090205828 12/388994 |
Document ID | / |
Family ID | 40954046 |
Filed Date | 2009-08-20 |
United States Patent
Application |
20090205828 |
Kind Code |
A1 |
Hermes; Robert E. ; et
al. |
August 20, 2009 |
Production and Delivery of a Fluid Mixture to an Annular Volume of
a Wellbore
Abstract
The methods described herein generally relate to preparing and
delivering a fluid mixture to a confined volume, specifically an
annular volume located between two concentrically oriented casing
strings within a hydrocarbon fluid producing well. The fluid
mixtures disclosed herein are useful in controlling pressure in
localized volumes. The fluid mixtures comprise at least one
polymerizable monomer and at least one inhibitor. The processes and
methods disclosed herein allow the fluid mixture to be stored,
shipped and/or injected into localized volumes, for example, an
annular volume defined by concentric well casing strings.
Inventors: |
Hermes; Robert E.; (Los
Alamos, NM) ; Bland; Ronald Gene; (Houston, TX)
; Foley; Ron Lee; (Magnolia, TX) ; Bloys; James
B.; (Katy, TX) ; Gonzalez; Manuel E.;
(Kingwood, TX) ; Daniel; John M.; (Germantown,
TN) ; Robinson; Ian M.; (Guisborough, GB) ;
Carpenter; Robert B.; (Tomball, TX) |
Correspondence
Address: |
CROWELL & MORING LLP;INTELLECTUAL PROPERTY GROUP
P.O. BOX 14300
WASHINGTON
DC
20044-4300
US
|
Assignee: |
Chevron U.S.A. Inc.
San Ramon
CA
Los Alamos National Security, LLC
Los Alamos
NM
Baker Hughes Incorporated
Houston
TX
Lucite International, Inc.
Cordova
TN
|
Family ID: |
40954046 |
Appl. No.: |
12/388994 |
Filed: |
February 19, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61064147 |
Feb 19, 2008 |
|
|
|
Current U.S.
Class: |
166/288 ;
166/292 |
Current CPC
Class: |
E21B 33/14 20130101;
E21B 33/13 20130101; Y10S 507/904 20130101; C09K 8/508
20130101 |
Class at
Publication: |
166/288 ;
166/292 |
International
Class: |
E21B 33/13 20060101
E21B033/13; E21B 43/00 20060101 E21B043/00; E21B 33/14 20060101
E21B033/14 |
Goverment Interests
STATEMENT OF FEDERAL RIGHTS
[0002] The United States government has rights in this invention
pursuant to Contract No. DE-AC52-06NA25396 between the United
States Department of Energy and Los Alamos National Security, LLC
for the operation of Los Alamos National Laboratory.
Claims
1. A process for delivering a mixture to a confined volume
comprising: (a) forming a mixture of at least one polymerizable
monomer and at least one inhibitor in a fluid; (b) transporting the
mixture to a second location; (c) delivering at least a portion of
the mixture to a localized volume at the second location; and (d)
sealing the localized volume to produce a confined volume
containing at least a portion of the mixture; wherein the
polymerizable monomer and the inhibitor are present in the mixture
in an amount determined from the following: (i) time elapsed
between forming the mixture in step (a) and sealing the localized
volume in step (d), (ii) a projected temperature conditions during
transportation in step (b), and expected pressure change in the
confined volume after sealing the mixture within the confined
volume.
2. The process according to claim 1, wherein the confined volume is
within a wellbore extending from the mudline to the bottom of the
wellbore depth or any annular volume thereof, and is filled with at
least a portion of the mixture.
3. The method according to claim 1, further comprising the step of
mixing at least one initiator into the mixture prior to delivering
the mixture to the localized volume.
4. The method according to claim 3, wherein the at least one
initiator is added in an amount determined from the following: (i)
time between adding the initiator and beginning polymerization of
the polymerizable monomer, (ii) a projected temperature profile of
mixture after addition of the initiator, (iii) reaction rate of the
initiator with the polymerizable monomer, and (iv) reaction rate of
the initiator with the inhibitor.
5. The method according to claim 1, further comprising mixing at
least one weighting agent with the mixture prior to step (c)
delivering at least a portion of the mixture to a localized
volume.
6. The method according to claim 1, wherein the volume is an
annular volume described by two concentric casing strings within a
well bore.
7. The method according to claim 1, wherein the polymerizable
monomer polymerizes within the confined volume with a decrease in
pressure with the confined volume.
8. The method according to claim 1, wherein the polymerizable
monomer is selected from the group consisting of acrylates,
methylacrylates, styrenics, N-vinyl amides, acrylamides,
methacrylamides, and vinyl urethanes.
9. The method according to claim 1, wherein the polymerizable
monomer is present in the mixture in an amount between about 0.5
weight percent and about 50 weight percent of the mixture and the
inhibitor is present in the mixture in an amount between about 1
and about 10,000 ppm.
10. The method according to claim 1, wherein the inhibitor is
selected from the group consisting of hydroquinone; hydroquinone
monomethyl ether; phenothiazine and derivatives thereof,
2,2,6,6-tetramethylpiperidin-1-oxyl free radical;
4-hydroxy-2,2,6,6-tetramethylpiperidin-1-oxyl free radical and
derivatives thereof, N-nitrosophenylhydroxylamine ammonium or
aluminum salts; N,N-diethylhydroxylamine, and mixtures thereof.
11. The method according to claim 3, wherein the initiator is
present in the mixture in amount between about 0.001 weight percent
and about 5 weight percent of the mixture.
12. The method according to claim 3, wherein the inhibitor is oil
soluble and the initiator is water soluble.
13. The method according to claim 1, wherein the mixture contains
droplets comprising the polymerizable monomer, wherein the droplets
have a diameter between about 10 and about 200 .mu.m.
14. The method according to claim 1, wherein the polymerizable
monomers in the mixture do not polymerize for at least 1 hour at
the second location prior to being delivered to the localized
volume in step (c).
15. The method according to claim 3, wherein the polymerizable
monomers in the mixture do not polymerize for at least 1 hour at
the second location after mixing at least one initiator into the
mixture and prior to being delivered to the localized volume in
step (c).
16. The method according to claim 1, wherein the at least one
polymerization inhibitor is present in an amount such that the
polymerizable monomers in the mixture do not polymerize for at
least five weeks prior to being delivered to the localized volume
in step (c).
17. A process for controlling pressure buildup within an annular
volume located between two casing strings within a wellbore,
comprising the steps of: (a) forming a mixture of at least one
polymerizable monomer and at least one inhibitor; (b) transporting
the mixture to a second location; (c) optionally mixing at least
one initiator into the mixture; (d) filling at least a portion of
the annular volume with the mixture; (e) sealing the annular
volume; and (f) heating the mixture within the sealed annular
volume such that the polymerizable monomer polymerizes with a
decrease in pressure within the sealed annular volume.
18. The process according to claim 17, wherein the sealed annular
volume within the wellbore extends from the mudline to the bottom
of the wellbore depth or any annular volume thereof, and is filled
with at least a portion of the mixture.
19. The process of claim 17, wherein the polymerizable monomer and
the inhibitor are present in the mixture in an amount determined
from the following: (i) time elapsed between forming the mixture in
step (a) and sealing the annular volume in step (e), (ii) a
projected temperature conditions during transportation in step (b),
and expected pressure increase in the annular volume after sealing
the mixture within the annular volume.
20. A process for delivering a mixture to an encapsulated volume
comprising: a) forming a first mixture of at least one
polymerizable monomer and at least one inhibitor in a water-based
fluid at a first location; b) transporting the first mixture to a
second location; c) adding at least one initiator to the first
mixture at the second location to form a second mixture; d)
delivering at least a portion of the second mixture to a localized
volume; and e) sealing the localized volume to produce an
encapsulated volume filled with at least a portion of the second
mixture.
21. The process according to claim 20, wherein the encapsulated
volume is within a wellbore extending from the mudline to the
bottom of the wellbore depth or any annular volume thereof, and is
filled with at least a portion of the second mixture.
22. The process according to claim 1, wherein at least a portion of
the polymerizable monomer polymerizes within the encapsulated
volume.
23. The process according to claim 1, further comprising mixing a
weighting agent with at least one of the first mixture and second
mixture prior to step (d).
24. The process according to claim 20, further comprising adding a
second quantity of the polymerizable monomer to at least one of the
first mixture and second mixture at the second location prior to
step (d).
25. The process according to claim 20, further comprising adding a
second quantity of the inhibitor to at least one of the first
mixture and second mixture at the second location prior to step
(d).
26. A process for delivering a mixture to an annular volume within
a well-bore comprising: a) forming a first mixture of at least one
monomer and at least one inhibitor in a water-based fluid at a
first location; b) transporting the first mixture to a second
location; c) optionally adding at least one initiator to the first
mixture at the second location to form a second mixture; d)
delivering at least a portion of the second mixture to an annular
volume located between two concentric casing strings within a
well-bore; and e) sealing the annular volume to produce an
encapsulated volume filled with at least a portion of the second
mixture.
27. The process according to claim 26, further comprising mixing a
weighting agent with at least one of the first mixture and second
mixture prior to step (d), wherein the weighting agent is selected
from the group consisting of brines, barite, hematite, calcium
carbonate, siderite, ilmenite, and mixtures thereof.
28. The process according to claim 26, further comprising adding a
second quantity of the monomer to at least one of the first mixture
and second mixture at the second location prior to step (d) and
adding a second quantity of the inhibitor to at least one of the
first mixture and second mixture at the second location prior to
step (d).
29. The process according to claim 26, wherein the encapsulated
volume within the wellbore extends from the mudline to the bottom
of the wellbore depth or any annular volume thereof, and is filled
with at least a portion of the second mixture.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to U.S. Provisional
Application Ser. No. 61/064,147, filed Feb. 19, 2008, which is
incorporated herein by reference in its entirety. The present
application also incorporates by reference the entire disclosures
of pending U.S. patent application Ser. No. 11/282,424, filed Nov.
18, 2005 and U.S. patent application Ser. No. 12/004,416, filed
Dec. 21, 2007 which is a continuation of U.S. patent application
Ser. No. 11/593,608, filed on Nov. 7, 2006, now abandoned.
FIELD OF ART
[0003] The methods described herein generally relate to preparing
and delivering a fluid mixture to a confined volume, specifically
an annular volume located between two concentrically oriented
casing strings within a hydrocarbon fluid producing well.
BACKGROUND
[0004] During the process of drilling a wellbore, such as an oil
well, individual lengths of relatively large diameter metal
tubulars are typically secured together to form a casing string or
liner that is positioned within each section of the wellbore. Each
of the casing strings may be hung from a wellhead installation near
the surface. Alternatively, some of the casing strings may be in
the form of liner strings that extend from near the setting depth
of a previous section of casing. In this case, the liner string
will be suspended from the previous section of casing on a liner
hanger. The casing strings are usually comprised of a number of
joints or segments, each being on the order of forty feet long,
connected to one another by threaded connections or other
connection means. These connections are typically metal pipes, but
may also be non-metal materials such as composite tubing. This
casing string is used to increase the integrity of the wellbore by
preventing the wall of the hole from caving in. In addition, the
casing string prevents movement of fluids from one formation to
another formation through which the wellbore passes.
[0005] Conventionally, each section of the casing string is
cemented within the wellbore before the next section of the
wellbore is drilled. Accordingly, each subsequent section of the
wellbore must have a diameter that is less than the previous
section. For example, a first section of the wellbore may receive a
surface (or conductor) casing string having a 20-inch diameter. The
next several sections of the wellbore may receive intermediate (or
protection) casing strings having 16-inch, 133/8-inch and 95/8-inch
diameters, respectively. The final sections of the wellbore may
receive production casing strings having 7-inch and 41/2-inch
diameters, respectively. When the cementing operation is completed
and the cement sets, there is a column of cement in the annulus
described by the outside surface of each casing string.
[0006] Subterranean zones penetrated by well bores are commonly
sealed by hydraulic cement compositions. In this application, pipe
strings such as casings and liners are cemented in well bores using
hydraulic cement compositions. In performing these primary
cementing operations, a hydraulic cement composition is pumped into
the annular space described by the walls of a well bore and the
exterior surfaces of a pipe string disposed therein. The cement
composition is permitted to set in the annular space to form an
annular sheath of hardened substantially impermeable cement which
supports and positions the pipe string in the well bore and seals
the exterior surfaces of the pipe string to the walls of the well
bore. Hydraulic cement compositions are also utilized in a variety
of other cementing operations, such as sealing highly permeable
zones or fractures in subterranean zones, plugging cracks or holes
in pipe strings and the like.
[0007] Casing assemblies comprising more than one casing string
describe one or more annular volumes between adjacent concentric
casing strings within the wellbore. Normally, each annular volume
is filled, at least to some extent, with the fluid which is present
in the wellbore when the casing string is installed. In a deep
well, the quantities of fluid within the annular volume (i.e., the
annular fluid) may be significant. Each annulus 1 inch thick by
5000 feet long would contain roughly 50,000 gallons, depending on
the diameter of the casing string.
[0008] In oil and gas wells it is not uncommon that a section of
formation must be isolated from the rest of the well. This is
typically achieved by bringing the top of the cement column from
the subsequent string up inside the annulus above the previous
casing shoe. While this isolates the formation, bringing the cement
up inside the casing shoe effectively blocks the safety valve
provided by nature's fracture gradient. Instead of leaking off at
the shoe, any pressure build up will be exerted on the casing,
unless it can be bled off at the surface. Most land wells and some
offshore platform wells are equipped with wellheads that provide
access to every casing annulus and an observed pressure increase
can be quickly bled off. On the other hand, most subsea wellhead
installations do not provide access to the casing annuli and a
sealed annulus may be created. Because the annulus is sealed, the
internal pressure can increase significantly in reaction to an
increase in temperature.
[0009] The fluids in the annular volume during installation of the
casing strings will generally be at or near the ambient temperature
of the seafloor. When the annular fluid is heated, it expands and a
substantial pressure increase may result. This condition is
commonly present in all producing wells, but is most evident in
deep water wells. Deep water wells are likely to be vulnerable to
annular pressure build up because of the cold temperature of the
displaced fluid, in contrast to elevated temperature of the
production fluid during production. The temperature of the fluid in
the annular volume when it is sealed will generally be the ambient
temperature, which may be in the range of from 0.degree. F. to
100.degree. F. (for example 34.degree. F.), with the lower
temperatures occurring most frequently in subsea wells with a
considerable depth of water above the well. During production from
the reservoir, produced fluids pass through the production tubing
at significantly higher temperatures. Temperatures in the range of
50.degree. F. to 300.degree. F. are expected, and temperatures in
the range of 125.degree. F. to 250.degree. F. are frequently
encountered.
[0010] The relatively high temperature of the produced fluids
increases the temperature of the annular fluid between the casing
strings, and increases the pressure against each of the casing
strings. Conventional liquids which are used in the annular volume
expand with temperature at constant pressure; in the constant
volume of the annular space, the increased fluid temperature
results in significant pressure increases. Aqueous fluids, which
are substantially incompressible, could increase in volume by
upwards of 5% during the temperature change from ambient conditions
to production conditions at constant pressure. At constant volume,
this increase in temperature may result in pressure increases up to
on the order of 10,000 psig. The increased pressure significantly
increases the chances that the casing string fails, with
catastrophic consequences to the operation of the well.
[0011] The annular pressure build up (APB) problem is well known in
the petroleum drilling/recovery industry. See: B. Moe and P.
Erpelding, "Annular pressure buildup: What it is and what to do
about it," Deepwater Technology, p. 21-23, August (2000), and P.
Oudeman and M. Kerem, "Transient behavior of annular pressure
buildup in HP/HT wells," J. of Petroleum Technology, v. 18, no. 3,
p. 58-67 (2005). Several potential solutions have been previously
reported: A. injection of nitrogen-foamed cement spacers as
described in R. F. Vargo, Jr., et. al., "Practical and Successful
Prevention of Annular Pressure Buildup on the Marlin Project,"
Proceedings--SPE Annual Technical Conference and Exhibition, p.
1235-1244, (2002), B. vacuum insulated tubing as described in J. H.
Azzola, et. al., "Application of Vacuum Insulated Tubing to
Mitigate Annular Pressure Buildup," Proceedings--SPE Annual
Technical Conference and Exhibition, p. 1899-1905 (2004), C.
crushable foam spacer as described in C. P. Leach and A. J. Adams,
"A New Method for the Relief of Annular Heat-up Pressure," in
proceedings,--SPE Annual Technical Conference and Exhibition, p.
819-826, (1993), D. cement shortfall, full-height cementation,
preferred leak path or bleed port, enhanced casing (stronger), and
use of compressible fluids as described in R. Williamson et. al.,
"Control of Contained-Annulus Fluid Pressure Buildup," in
proceedings, SPE/IADC Drilling Conference paper Number 79875
(2003), and E. use of a burst disk assembly, as described by J.
Staudt in U.S. Pat. No. 6,457,528 (2002) and U.S. Pat. No.
6,675,898 (2004). These prior art examples, although potentially
useful, do not provide full protection against the APB problem due
to either difficulties in implementation or prohibitory costs, or
both.
SUMMARY
[0012] A process for delivering a mixture to a confined volume is
disclosed herein. The process comprises (a) forming a mixture of at
least one polymerizable monomer and at least one inhibitor in a
water-based fluid; (b) transporting the mixture to a second
location; (c) delivering at least a portion of the mixture to a
localized volume at the second location; and (d) sealing the
localized volume to produce a confined volume containing at least a
portion of the mixture. The polymerizable monomer and the inhibitor
are present in the mixture in an amount determined from the
following: (i) time elapsed between forming the mixture in step (a)
and sealing the localized volume in step (d), (ii) a projected
temperature conditions during transportation in step (b), and
expected pressure change in the confined volume after sealing the
mixture within the confined volume.
[0013] Additionally disclosed is a process for controlling pressure
buildup within an annular volume located between two casing strings
within a wellbore. The process comprises (a) forming a mixture of
at least one polymerizable monomer and at least one inhibitor; (b)
transporting the mixture to a second location; (c) optionally
mixing at least one initiator into the mixture; (d) filling at
least a portion of the annular volume with the mixture; (e) sealing
the annular volume; and (f) heating the mixture within the sealed
annular volume such that the polymerizable monomer polymerizes with
a decrease in pressure within the sealed annular volume.
[0014] A process for delivering a mixture to an encapsulated volume
is also disclosed. The method comprises (a) forming a first mixture
of at least one polymerizable monomer and at least one inhibitor in
a water-based fluid at a first location; (b) transporting the first
mixture to a second location; (c) adding at least one initiator to
the first mixture at the second location to form a second mixture;
(d) delivering at least a portion of the second mixture to a
localized volume; and (e) sealing the localized volume to produce
an encapsulated volume filled with at least a portion of the second
mixture.
[0015] Further disclosed is a process for delivering a mixture to
an annular volume within a well-bore comprising: (a) forming a
first mixture of at least one monomer and at least one inhibitor in
a water-based fluid at a first location; b) transporting the first
mixture to a second location; c) adding at least one initiator to
the first mixture at the second location to form a second mixture;
d) delivering at least a portion of the second mixture to an
annular volume located between two concentric casing strings within
a well-bore; and e) sealing the annular volume to produce an
encapsulated volume filled with at least a portion of the second
mixture.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. 1 illustrates an exemplary well comprising a localized
volume set to receive a fluid mixture.
[0017] FIG. 2 illustrates the exemplary well comprising a localized
volume of FIG. 1 encapsulated or sealed such that it contains a
prepared fluid mixture.
[0018] FIG. 2A is a section view of FIG. 2 detailing a fluid
arrangement within a sealed annular volume according to the present
invention.
[0019] FIG. 3 illustrates a flow process of the present invention
for production and delivery of a fluid mixture to a localized
volume.
[0020] FIG. 4 illustrates a flow process of the present invention
for production and delivery of a fluid mixture to a localized
volume while ensuring sufficient monomer and inhibitor are
contained in the fluid mixture.
[0021] FIG. 5 illustrates a flow process of the present invention
for production and delivery of a fluid mixture including a
weighting agent to a localized volume.
[0022] FIG. 6 illustrates a flow process of the present invention
combining the flow processes of FIGS. 4 and 5.
[0023] Corresponding reference characters indicate corresponding
like elements throughout multiple views. Although the figures
represent embodiments of the present invention, the figures are not
necessarily to scale and certain features may be exaggerated in
order to better illustrate and explain the present invention.
DETAILED DESCRIPTION
[0024] Among other factors, it has been discovered that processes
and methods disclosed herein postpone polymerization of the
polymerizable monomers in the fluid mixture for a significant
period of time. During such postponement, the fluid mixture can be
stored, shipped and/or injected into localized volumes, for
example, an annular volume defined by concentric well casing
strings.
[0025] The fluid mixtures disclosed herein are useful in
controlling pressure in localized volumes. As such, the fluid
mixtures can be used to replace at least a portion of a first fluid
within the localized volume with the fluid mixtures as disclosed
herein. The localized volume is sealed to produce a confined
volume.
[0026] The fluid mixture as disclosed herein comprises at least one
polymerizable monomer and at least one initiator in a fluid. This
fluid may be a water-based fluid, oil-based fluid, or
synthetic-based fluid. The polymerizable monomer within the fluid
mixture polymerizes with a decrease in pressure within the confined
volume. The polymerizable monomer may polymerize with an increase
in temperature or the polymerizable monomer may polymerize over
time with or without the use of an initiator. The monomer
polymerizes with a decrease in pressure within the confined volume
such that the final pressure will be less than had the confined
volume contained only the first fluid. This final pressure may be
greater than, equal to, or less than the initial pressure when the
fluid mixture is delivered into the confined volume; however, it is
less than had the confined volume contained only the first
fluid.
Definitions
[0027] As used herein, the term "methyl methacrylate (MMA)
monomers" refers to methyl 2-methyl-2-propenoate monomers
represented by the following formula.
##STR00001##
MMA monomers polymerize to form polymethyl methacrylate (PMMA),
which is represented by the formula:
##STR00002##
where n.gtoreq.2.
[0028] "Inhibitor" means a chemical compound that delays monomers
from polymerizing to form a polymer.
[0029] "Weighting agent" refers to a chemical compound that
increases the density of a substance to which it is added. Suitable
examples include brines (e.g. KCl, NaCl), barite, hematite, calcium
carbonate, siderite, and ilmenite.
[0030] "Polymerization initiator" refers to a chemical compound
that begins polymerization of monomers to form a polymer.
[0031] "Optional" or "optionally" means that the subsequently
described event, circumstance or component may, but need not, be
present. Thus, the description includes instances where the event,
circumstance, or component is present and instances in which it is
not present.
[0032] "Spacer fluid" means any liquid used to physically separate
one special-purpose liquid from another.
[0033] A process for delivering a mixture to a confined volume, as
described herein, comprises forming a mixture of at least one
polymerizable monomer and at least one inhibitor in a water-based
fluid. The fluid may also optionally comprise at least one
initiator. Accordingly, in one embodiment the fluid mixture
includes polymerizable monomers and inhibitor, and in another
embodiment, the fluid mixture includes polymerizable monomers,
inhibitor, and initiator.
[0034] Once prepared, this fluid mixture can be injected into an
annular volume located between a casing or casing string and a
wellbore wall and left for an extended period of time. The
polymerizable monomers in the fluid mixture may not polymerize to a
significant degree for a period of time. After this period has
elapsed, the polymerizable monomers polymerize resulting in a
decrease in pressure within the annular volume. The relative
amounts of polymerizable monomer and initiator are selected in
order to postpone polymerization of the monomers for a desired
period of time and to achieve the decrease in pressure desired
within the annular volume. Analysis can be performed using any
suitable analytical technique which will allow the determination of
the monomer and/or inhibitor concentration prior to use.
[0035] The amount of monomers and inhibitor can be calculated by
one of skill in the art using the following parameters: (1) time
elapsed between forming the mixture and sealing the localized
volume; a projected temperature conditions during transportation of
the mixture; and expected pressure change in the confined volume
after sealing the mixture within the confined volume. The expected
pressure change is at least in part based upon the projected
temperature conditions of the wellbore. The projected temperature
conditions are based on an estimation of the temperature conditions
that will be experienced by the fluid mixture. These temperature
conditions include the temperature when the mixture is prepared,
the temperature conditions during transportation, and the
temperatures encountered by the mixture after it is injected into
the confined volume.
[0036] The polymerizable monomers can be present in the fluid
mixture in an amount between about 0.5 weight percent and about 50
weight percent. The polymerizable monomers can be water soluble
monomers and oil soluble monomers. Both a water soluble monomer and
a water insoluble monomer, when added to the annular volume, can
polymerize, with an accompanying decrease in volume (and associated
decrease in pressure within the annular volume). Such a decrease in
volume would, in the confined volume of the sealed annulus, result
in a decrease in pressure, within the confined volume, relative to
a similar system without polymerization of the particular monomers
of the present invention.
[0037] The polymerizable monomer can be selected from acrylates,
methylacrylates, styrenics, N-vinyl amides, acrylamides,
methacrylamides, and vinyl urethanes. Non-limiting examples of
styrenics include vinyl benezene and derivatives. Non-limiting
examples of acrylic monomers include acrylamide, methacrylamide,
their derivatives, acrylic acid, methacrylic acid, their salts,
acid salts and quaternary salts of N,N-dialkylaminoalkyl acrylates
or methacrylates, acidic salts of diallylamine, diallyldialkyl
ammonium salts, sulfoalkyl acrylates or methacrylates,
acrylamidealkyl sulfonic acids and their salts, and the like. More
preferably, the acrylic monomers include methyl acrylate, methyl
methacrylate, and mixtures thereof Non-limiting examples of other
vinyl monomers that could be practical for this in-situ
polymerization process include other acrylic esters, methacrylic
esters, butadiene, styrene, vinyl chloride, N-vinylpyrrolidone,
N-vinylcaprolactam, or other such oil and/or water soluble
monomers.
[0038] With the polymerization of the monomers in the fluid
mixture, a reduction in volume results from the polymerization
process. Such a decrease in volume would, in the confined volume,
result in a decrease in pressure, within the confined volume,
relative to a similar system without polymerizable monomers. This
decrease in pressure assists in controlling the pressure within the
confined volume.
[0039] The fluid mixture as disclosed herein further comprises an
inhibitor. The polymerization inhibitor can be present in the fluid
mixture in an amount between about 1 ppm and about 10,000 ppm. The
inhibitor can be oil or water soluble. In one embodiment the
inhibitor is a high temperature inhibitor; the inhibitors can be
stable up to 100.degree. F. for several hours. In one embodiment
the inhibitor is oil soluble.
[0040] Inhibitors are well known to those of skill in the art.
Inhibitors are commercially available. Suitable inhibitors trap
free radicals. Such inhibitors include those needing oxygen to
provide inhibition, such as phenolic compounds hydroquinone (HQ),
hydroquinone monomethyl ether (MEHQ), and the like. Other
inhibitors which do not need oxygen for the inhibitory effect
include phenothiazine (PTZ) and derivatives thereof,
2,2,6,6-tetramethylpiperidin-1-oxyl free radical (TEMPO),
4-hydroxy-2,2,6,6-tetramethylpiperidin-1-oxyl free radical
(4-hydroxyTEMPO), and derivatives thereof,
N-nitrosophenylhydroxylamine ammonium or aluminum salts; and
N,N-diethylhydroxylamine. Mixtures of inhibitors can be used.
[0041] The fluid mixture comprising polymerizable monomers and
inhibitor is prepared at a first location and then transported to a
second location. This first location may be remote from the first
location, for example 100 miles or more. The first location may be
on-shore or off-shore. The second location is located at the site
of the confined volume to which the fluid mixture is to be
delivered. The second location may be on-shore or off-shore. In one
embodiment, the first location is on-shore and the second location
is off-shore. The off-shore location can be an off-shore platform,
such as a jack-up rig, semi-submersible rig, or free-floating drill
ship, or any other apparatus or ship which is typically used for
drilling off-shore wells.
[0042] A sizeable period of time may elapse after preparation of
the fluid mixture, during transportation from the first location to
the second location and until the fluid mixture is delivered to the
localized volume. For example, at least five weeks may elapse.
[0043] The fluid mixture may be transported by conventional means
well known to those of skill in the art, including tanker vehicles
over land and tanker ships over water to off-shore locations.
[0044] The fluid mixture may optionally comprise one or more
initiators. The initiator can be oil or water soluble. In one
embodiment the initiator is water soluble. In one embodiment the
initiator is a high temperature initiator. In an embodiment the
initiator is oil soluble. Initiators are well known to those of
skill in the art. Initiators are commercially available. Suitable
polymerization initiators include free radical initiators. Such
initiators include azo-compounds, organic peroxides, and inorganic
peroxides (e.g. potassium persulfate). Azo-initiators can be
suitable as high temperature initiators.
[0045] An azo-type initiator produces nitrogen gas as a by-product
during the polymerization process. The resulting gas phase
component which is generated in the confined annular volume, being
a compressible fluid, can contribute to the control of the pressure
within the confined annular volume as the annular fluid is being
heated by the product fluid passing through the production tubing.
A peroxide initiator may also be used, depending on the temperature
and chemical constraints of the product fluid. Alternatively, a
redox initiator system such as ammonium persulfate and the
activator N,N,N'N'-tetramethylethylenediamine, or potassium
persulfate and the activator ferrous sulfate/sodium bisulfite could
also be used if encapsulated as mentioned above to control the
timing of when the polymerization occurs.
[0046] When the fluid mixture comprises initiator, the initiator
may be added at the second location prior to the fluid mixture
being delivered to the confined volume. The initiator may be added
just prior to the fluid mixture being delivered to the confined
volume or the initiator may be added and then the fluid mixture may
be stored for some period before being delivered to the confined
volume. This period may be up to several hours, for example 1 to 6
hours.
[0047] The amount of initiator added to the mixture can be
determined from the following parameters: (1) time desired between
adding the initiator and beginning polymerization of the
polymerizable monomer; a projected temperature profile of the
mixture after addition of the initiator; reaction rate of initiator
with the polymerizable monomer; and reaction rate of the inhibitor
with the initiator. The initiator can be present in the fluid
mixture in an amount between about 0.001 weight percent and about 5
weight percent of the mixture.
[0048] The method of preparing a trapped annular pressure fluid, as
described herein, may further include mixing at least one weighting
agent with the polymerizable monomers and the inhibitor. If the
weighting agent is used, it increases the density of the fluid
mixture. The density increases as the amount of weighting agent
increases and should be adjusted so that it falls within a range
suitable for pumping the fluid mixture within the aforementioned
annular volume. Suitable weighting agents are well known to those
of skill in the art and include, for example, brines, barite,
hematite, calcium carbonate, siderite, ilmenite, and mixtures
thereof. According to one embodiment of the method as described
herein, the at least one weighting agent is barite or barium
sulfate (BaSO.sub.4), which is conventionally used to increase the
density of oil well drilling fluid.
[0049] As previously described, the fluid mixture can be prepared
by either one mixing step or two, separate mixing steps, wherein
the second mixing step occurs some time after the initial mixing
step with the initial mixing step occurring at the first location
and the second mixing step occurring at the second location remote
from the first location. The initial mixing step can involve mixing
the polymerizable monomers, the at least one inhibitor, and
optionally at least one weighting agent. The subsequently mixing
step can involve mixing the at least one initiator, mixing
additional polymerizable monomer, and mixing additional
inhibitor.
[0050] The resulting mixture can cover the range of true emulsions
and suspensions. The droplets can either be in the oil continuous
phase (i.e., totally solubilized within the oil or synthetic-based
fluid) or emulsified within the water phase (droplets between 0.1
and 200 microns), or in the case of water soluble monomers,
dissolved in the water phase of any water based drilling/spacer
fluids. In one embodiment the polymerizable monomers are present in
the fluid as droplets and the inhibitor is oil soluble and the
initiator is water soluble.
[0051] In one embodiment the fluid mixture is an emulsion of
polymerizable monomers and oil soluble inhibitor. Emulsification
ensures that the monomers and inhibitor are in good contact with
each other. The monomers and inhibitor may be mixed such that
droplets comprise the monomers and these droplets have a diameter
between about 10 .mu.m and about 200 .mu.m.
[0052] The mixture of the polymerizable monomers with the
inhibitors helps to prevent and/or delay premature polymerization.
After the inhibitor is expended, the monomers will polymerize,
particularly when exposed to favorable conditions, including
increased temperature and optionally initiator. The monomers will
polymerize on their own. Accordingly, including initiator in the
fluid mixture to facilitate polymerization is optional.
[0053] Upon the addition of initiator, the initiator will react
with polymerization inhibitor. Excess initiator in the fluid
mixture will assist in triggering polymerization of the
monomers.
[0054] The at least one initiator can be water soluble or
water-insoluble. Possible polymerization initiators include
azo-type initiators, peroxide initiators, an ammonium
persulfate/N,N,N',N'-tetramethylethylene diamine redox initiator
system, and a potassium persulfate/ferrous sulfate/sodium bisulfate
initiator system. Azo-type initiators are desirable because they
produce nitrogen gas as a by-product. Since nitrogen gas is a
compressible fluid, it can assist contribute to pressure reduction
within the annular volume.
[0055] One or more additives can also be mixed into the fluid
mixture comprising monomers, inhibitor, optional initiator, and
optional weighting agent. Exemplary additives include surfactants,
pH buffers, biopolymers, emulsifiers, defoamers, dispersants, and
anti-static agents. Addition of a surfactant stabilizes an
emulsion. Addition of a pH buffer counteracts any pH change that
results when any cement remains within the annular volume after the
trapped annular pressure fluid is injected to the annular volume.
Addition of a biopolymer affects the viscosity of the fluid
mixture. Addition of an anti-static agent can prevent build up of
static charge and sparking. The antistatic agent preferably
comprises hydrophilic and hydrophobic groups.
[0056] In practice, the fluid mixture can be delivered into an
annular volume defined by two, concentrically arranged casing
strings. Therein, the fluid displaces at least a portion of fluid
already contained within such annular space. The annular space is
generally filled with fluid present when the innermost casing
string is installed. Conventional fluids which may initially be
present in the annular volume include a drilling fluid or a
completion fluid, depending on the circumstances of the drilling
operation. In any event, this fluid is an incompressible fluid.
[0057] In order to understand implementation of the trapped annular
pressure fluid to control pressure within the annular volume, a
discussion of well construction using the trapped annular pressure
fluid is instructive.
[0058] It should be appreciated the number of casing strings and
the depth of the well varies from well to well. For simplicity, the
fluid initially present in the annular volumes defined by the
various casing strings is called drilling fluid.
[0059] A well is formed by drilling into earth with a drill rig to
provide a hole, known as a wellbore. As the wellbore is drilled, it
is necessary to insert a series of casing strings into the wellbore
to prevent the sides of the wellbore from collapsing inwardly into
the wellbore. Initially, the wellbore is drilled to a first depth
and a casing string is inserted and sealed against the wellbore
wall by a cement plug. Next, the wellbore is drilled deeper and
with a narrower diameter to a second depth and a casing string is
inserted creating an annular volume between the casing strings. The
annular volume is in fluid communication with the body of the
wellbore at the second depth. At this point, the annular volume is
filled with drilling fluid and the trapped annular pressure fluid
(the fluid mixture as disclosed herein) must be introduced into the
annular volume in order to replace at least a portion of the
drilling fluid.
[0060] This can be accomplished in one of two manners. The trapped
annular pressure fluid can be introduced into the body of the
wellbore such that it passes downwardly through the body in
relatively pure form in the form of a plug or pill, enters the
annular volume at the second depth, and passes upwardly through the
annular volume driving the drilling fluid originally in the annular
volume ahead of the trapped annular pressure fluid and out of the
annular volume. Alternatively, the trapped annular pressure fluid
can be introduced into the top of the annular volume. Introducing
fluid through the upper end of the annular volume is commonly
referred to as "bull-heading." After a sufficient amount of the
trapped annular pressure fluid has been added to the annular
volume, the annular volume is sealed at its lower end by a concrete
plug, and at its upper end by a casing annular plug.
[0061] The wellbore is drilled even deeper with an even narrower
diameter to a third depth and a casing string is inserted creating
an annular volume between the casing strings. The annular volume is
in fluid communication with the body of the wellbore at the third
depth. At this point, the annular volume is filled with drilling
fluid and the trapped annular pressure fluid (the fluid mixture as
disclosed herein) must be introduced into the annular volume in
order to replace at least a portion of the drilling fluid therein.
As with previous annular volume, this can occur in one of two ways
as described above. After a sufficient amount of the trapped
annular pressure fluid has been added to the annular volume, the
annular volume is sealed at its lower end by a concrete plug and at
its upper end by a casing annular plug.
[0062] Finally, the wellbore is drilled deeper with a narrower
diameter to the wellbore terminus. The terminus may be a temporary
terminus because the wellbore may be extended further at a later
time. A casing string, which is the final member of the casing
assembly, is inserted into the wellbore creating an annular volume
between the casing strings. The volume of the wellbore itself is
then defined by the cylindrically shaped space within the casing
string. During well production, production fluid (e.g. oil, natural
gas) flows through this wellbore volume. The annular volume is in
fluid communication with the wellbore volume at the terminus. At
this point, the annular volume is filled with drilling fluid and
the trapped annular pressure fluid must be introduced into the
annular volume in order to replace at least a portion of the
drilling fluid. The trapped annular pressure fluid can be
introduced into the wellbore volume such that it passes downward
through the volume in relatively pure form in the form of a plug or
pill, enters the annular volume at the terminus, and passes
upwardly through the annular volume driving the drilling fluid
originally in the annular volume ahead of the trapped annular
pressure fluid and out of the annular volume. As an alternative,
the trapped annular pressure fluid can be introduced into the top
of the annular volume. After a sufficient amount of trapped annular
pressure fluid has been added to the annular volume, the annular
volume is sealed at its lower end by a concrete plug and at its
upper end by a casing annular plug.
[0063] The amount of trapped annular pressure fluid supplied to the
annular volumes is a matter of engineering choice, depending on the
amount of pressure which can be tolerated inside the annular
volumes once they are sealed. This amount is further influenced by,
for example, the size of the well system, the temperature of the
trapped annular pressure fluid when it is supplied to the annular
volume, the temperature of the trapped annular pressure fluid in
the annular volume, the temperature of the production fluids (e.g.
oil, natural gas) that will be produced in the well, projected
temperature of the trapped annular pressure fluids within the
annular volume during production, design and specifications of the
casing string, and the like.
[0064] The temperatures within the annular volumes prior to
production are significantly lower than the temperatures within the
annular volumes during production. If the well is onshore,
generally the temperatures within the annular volumes are between
approximately 0.degree. F. and 150.degree. F. But if the well is an
offshore, subsea well, the temperatures within the annular volumes
can be less than 60.degree. F., or less than 40.degree. F., for
example, between approximately 25.degree. F. and 35.degree. F.
[0065] During production, hydrocarbon production fluids flow
through the wellbore body. This hydrocarbon production fluid can
have temperatures in the range of approximately 50.degree. F. to
400.degree. F. Most frequently, temperatures in the range of
approximately 125.degree. F. to 250.degree. F. are encountered.
Heat from this hotter, hydrocarbon production fluids transfers to
the fluid, including the trapped annular pressure fluid, within the
annular volumes thereby raising the temperatures within the annular
volumes. Since each annular volume is a confined area, pressure
within each annular volume increases with increase in temperature.
If the temperatures encountered are high enough, the corresponding
pressure can deform or fracture the casing strings defining the
annular volume. But if pressure is eventually reduced by some means
so that the pressure cannot climb to this "deforming" or "fracture"
pressure, the casing strings will remain intact and the well will
continue to function properly.
[0066] The trapped annular pressure fluid as described herein
reduces pressure within the annular volume. The polymerizable
monomers occupy a considerably larger volume, up to 20% more
volume, than their counterpart solid polymer. See, for example,
"Acrylic and Methacrylic Ester Polymers," in Encyclopedia of
Polymer Science and Engineering, 2nd Edition, J. Kroschwitz, ed.,
John Wiley & Sons, Inc., Volume 1, Table 20, p. 266 (1985) and
D. A. Tildbrook, et al., "Prediction of Polymerization Shrinkage
Using Molecular Modeling," J. Poly. Sci.; Part: B Polymer Physics,
41, 528-548 (2003). Thus, polymerization of the monomers reduces
pressure within the annular volume.
[0067] The temperatures encountered after preparation prior to
transportation, during transportation of the fluid mixture, storage
after transportation prior to delivery, and in the confined volume
after delivery prior to hydrocarbon production, determines in part,
the amount of monomer and inhibitor, and optional initiator, added
to the mixture and the time at which the monomers polymerize.
Accordingly, a time and temperature history until sealing the
confined volume is utilized in determining the amount of monomer,
inhibitor, and optional initiator. The mixing occurs at relatively
low temperatures, for example, between approximately 0.degree. F.
and 100.degree. F. During transportation, the mixture may encounter
temperatures between approximately 0.degree. F. and 120.degree. F.
As indicated above, temperature gradually rises within the annular
volume to a relatively high temperature due to heat transfer from
the hydrocarbon production fluid. These temperatures affect the
reaction rate between the free radicals and inhibitor, free
radicals and monomers, and inhibitor and initiator, respectively.
Higher temperatures increase these reaction rates and, therefore,
decrease the time period until polymerization. The rate of
hydrocarbon production can also be adjusted initially to achieve
the desired reaction rate and polymerization rate.
[0068] Days, weeks, or months may elapse between preparation of the
trapped annular pressure fluid (the fluid mixture as disclosed
herein) and the desired time of polymerization of the monomers.
[0069] In one embodiment, the fluid mixture may be stored and/or
transported for at least five weeks. This facilitates shipment of
the mixture from a first location (e.g. an on-shore location) to a
second location (e.g., an offshore location). The fluid mixture may
also be stored at the second location prior to delivery to the
localized volume. The fluid mixture may be stored for a period of
minutes up to several hours (e.g., 1 to 6 hours). This facilitates
use of the fluid mixture as described herein.
[0070] The following detailed description should be read with
reference to the figures in which like elements in different
figures are numbered identically. The figures depict selected
embodiments and are not intended to limit the scope of the
invention. The embodiments disclosed below are not intended to be
exhaustive or to limit the invention to precise forms. Rather, the
embodiments are chosen and described so that others skilled in the
art may utilize their teachings. Those of skill in the art should,
in light of the present disclosure, appreciate that many
modifications can be made to the selected embodiments described and
still obtain a like or similar result without departing from the
spirit and scope of the present invention. It will be understood
that embodiments shown in the figures and described below are
merely for illustrative purposes, and are not intended to limit the
scope of the invention as defined in the claims that follow.
[0071] The present invention is generally directed to a process for
producing and delivering a fluid mixture to a localized volume,
wherein the localized volume is sealed subsequent to delivery of
the fluid mixture and thereafter, the fluid mixture will decrease
in specific volume as the temperature of the fluid mixture is
increased. The fluid mixture includes at least one monomer that may
begin to polymerize when exposed to elevated temperatures as
compared to ambient conditions. Considering the monomer is
typically emulsified within the fluid mixture at a production plant
location and then transported to the localized volume, which may
take days or even weeks, it is often exposed to elevated
temperatures prior to being introduced into the localized volume.
For instance, during transport to an offshore rig, it may overheat
in a vessel tank while pending delivery. This often causes
undesired premature polymerization detracting from the objective of
utilizing the fluid mixture. The present invention includes
addition of an inhibitor to the fluid mixture to eliminate
premature polymerization, as well as, optionally an initiator to
counteract the results of the inhibitor once the fluid mixture is
encapsulated within the localized volume.
[0072] Representatively illustrated in FIG. 1 is an embodiment of
the present invention, wherein a localized volume is ready for
delivery of a prepared fluid mixture. Wellbore 10 has previously
been drilled into terrain 12 using drill string 40, and casing
string assembly 20, comprising at least two connected concentric
casing (22, 24, 26, 28), has already been installed. The oil rig
wellhead installation assembly including supporting means for
supporting the drill string 40, for installing the casing string
assembly 20, sealing the casing string assembly 20, and for
supplying the fluids to the wellbore 10, is not shown. In FIG. 1,
casing 22 is the largest diameter casing of casing string assembly
20 and hence was the first to be installed. Subsequent to
installation, casing 22 was sealed against the wellbore 10 by a
cement plug 30. Wellbore 10 was then drilled deeper and casings 24,
26 were correspondingly installed and sealed at or near one end
against the wellbore 10 by cement plugs 32, 34 respectively. In
addition to sealing casings to the wellbore, cement plugs may also
bond the casings to adjacent concentric casings. Hence in addition
to sealing to the wellbore 10, cement plug 32 bonds casing 24 to
casing 22 and cement plug 34 bonds casing 26 to casing 24.
[0073] Particular attention is now directed to casing 28, which has
been installed to extend in close proximity to wellbore terminus 14
such that there is a gap 18 in between wellbore terminus 14 and
casing end 36 of casing 28. It is clear that terminus 14 may be
temporary, such that the wellbore may be drilled deeper once casing
28 is intact. Alternatively, casing 28 may extend to the final
target depth and the wellbore 10 will not be drilled deeper prior
to when production commences. A localized annular volume 50,
confined by the inside surface of casing 26 and the outside surface
of casing 28, is filled with a fluid. Typically this fluid is
present within the wellbore volume 16 when casing 28 is installed
and may comprise one or more fluids, such as drilling fluid or
completion fluid, depending on the circumstances of the drilling
operation. Regardless, the properties of the fluid within the
annular volume 50 are selected to meet the needs of the wellbore
drilling operator and can be considered a standard incompressible
fluid such that the density of the fluid essentially remains
constant during thermal and pressure fluctuations. Thus, when the
fluid is confined to a particular volume a temperature increase of
the fluid generates a corresponding pressure increase as the
specific volume negligibly changes. Fluid may freely pass in
between annular volume 50 and wellbore volume 16 via the gap 18
beneath casing end 36 of casing 28. The opposing end of the annular
volume 50, designated by 52, is in fluid communication with
wellhead installation assembly (not shown), such that fluids
exiting annular volume 50 may be recovered. For instance, drilling
fluid or mud might be retrieved and passed through a filter to
remove separated rock content such that it may eventually be
recycled back to the drill bit for future drilling.
[0074] In the process of the invention, a prepared fluid mixture is
delivered to annular volume 50. Delivery of the prepared fluid
mixture typically occurs in accordance with two generally known
methods: (1) The prepared fluid mixture may be introduced to
wellbore volume 16 through wellbore opening 54 and pumped downward
until reaching wellbore terminus 14, at which point it passes
through gap 18 below casing string end 36 of casing string 28 into
annular volume 50. The standard incompressible drilling or
completions fluid previously occupying annular volume 50 is
therefore pushed out through annular volume wellhead opening 52.
(2) The prepared fluid mixture is pumped down directly from the top
of annular volume 50 through annular volume wellhead opening 52
defined by the exterior of casing string 28 and the interior of
casing string 26. The standard incompressible drilling or
completions fluid previously occupying the annular volume is
therefore pushed back into wellbore volume 16 through gap 18. This
process is typically coined "bull-heading" within the petroleum
industry's drilling/recovery sector. In the process of the
invention, at least a portion of the prepared fluid mixture is
supplied to the localized or annular volume. The actual quantity of
the prepared fluid mixture delivered may vary depending on a number
of well specific factors such as upon well depth and location, the
casing string assembly load limitations, localized temperatures and
pressures within the well system during drilling and completions,
and temperatures and pressures expected within the well system
during production. Characteristics of the prepared fluid mixture
(e.g., density, composition) may also influence this quantity.
[0075] Upon sufficient delivery of the prepared fluid mixture to
annular volume 50, annular volume 50 is encapsulated as depicted in
FIG. 2. Similar to cement plugs 30, 32, 34, a cement plug 38 acts
as a binder sealing the exterior of casing 28 to the wellbore wall.
Cement plug 38 likewise bonds the exterior of casing 28 to the
interior of casing 26 preventing fluid transfer in between the
casings. Generally, the wellhead installation assembly (not shown)
also includes casing annulus seals 56 for enclosing the wellhead;
thus covering casing openings, such as opening 52 (FIG. 1) of
annular volume 50, and fully encapsulating annular volume 50.
Therefore, the encapsulated volume represented by annular volume 50
now contains and prevents escape of at least a portion of the
prepared fluid mixture. The prepared fluid mixture, unlike the
drilling or completions fluid, is to be considered a compressible
fluid such that the density or inversely proportional specific
volume does not remain constant when undergoing temperature or
pressure fluctuations. Thus, as the temperature within the wellbore
rises during production, the prepared fluid mixture becomes more
compact or dense and a reduction in specific volume occurs. This
translates to an overall pressure reduction within the annular
volume 50 as compared to that of a conventional system wherein the
annular volume 50 is filled completely with an incompressible
fluid. Likewise, the process shown in FIGS. 1 and 2 may have
already occurred for previous annular volumes within the drill
string assembly 20, such that the prepared fluid mixture may be
present in the sealed annular volumes between previous casings 26
and 24 or casings 24 and 22.
[0076] In the prior art, for the seal to adhere properly to the
wellbore and the casings, a spacer fluid is cycled through directly
before delivery of the cement slurry. The spacer fluid generally
comprises a chemically treated aqueous solution, often containing a
large number of surfactants and additives, that washes the surfaces
of the casings and wellbore so that the surfaces may obtain a
strong bond with the cement while it sets. The spacer fluid also
may help to facilitate ideal hardening conditions for the slurry by
inducing a particular flow regime as the slurry is pumped into the
annular volume. Furthermore, it may also act as a buffer separating
other fluids from the cement slurry while it is hardening so that
the cement slurry does not become contaminated. In accordance with
the present invention, FIG. 2A shows a section view of FIG. 2
detailing a fluid arrangement within annular volume 50 according to
the present invention. The prepared fluid mixture or second mixture
122 is in direct fluid contact with the cement slurry during
delivery and remains in contact with the cement plug 38 once the
slurry has hardened, as depicted in FIG. 2A. Second mixture 122 may
be prepared with a number of additives and surfactants such that it
can perform the roles of the previously used spacer fluid. Thus,
second mixture 122 may be used to cleanse the spacers and wellbore,
assist in pumping conditions of the cement slurry, and act as a
buffer interface ensuring the cement slurry does not become
contaminated. Examples of the additives and surfactants that may be
present within second mixture 122 include accelerators, retarders,
dispersants, emulsifiers, defoamers, and pH stabilizers. Other
additional special additives may be utilized as well to fulfill a
specific role. In some embodiments, fluid 124 positioned adjacent
second mixture 122 comprises a drilling or completions fluid used
by the drilling practitioner. In these embodiments, annular volume
50 was originally filled completely with fluid 124 before second
mixture 122 was pumped into annular volume 50 and a portion of
fluid 124 was pushed out of annular volume though opening 52 (FIG.
1). In other embodiments, fluid 124 may comprise a spacer fluid
that assists second mixture 122 in cleansing the spacers 26, 28 and
wellbore.
[0077] FIG. 3 illustrates a flow process of the present invention
for production and delivery of a fluid mixture to a localized
volume. In a first location 100, a first mixture 120 is produced.
Generally first location 100 is land based and represents a
manufacturing plant of some sort. First mixture 120 comprises a
mixture of a solvent 110, monomer 112, and inhibitor 114. Solvent
110 may comprise any liquid composition in which monomer 112 and
inhibitor 114 are able to dissolve, for forming first mixture 120.
Solvent 110 may be an aqueous solvent or an organic solvent. It may
also contain a number of chemical additives or surfactants.
Preferably, first mixture 120 contains enough solvent 110 to fully
dissolve or disperse both monomer 112 and inhibitor 114. Monomer
112 may comprise any single monomer or a combination of multiple
monomers, permitted that once emulsified in first mixture 120,
first mixture 120 will decrease in specific volume under increased
temperatures, assuming inhibitor 114 is not yet present. In certain
embodiments, monomer 112 comprises one or more acrylates and
methacrylates. Both acrylates and methacrylates easily form
polymers as the double bonds found in their vinyl groups, two
carbon atoms double bonded to each other and attached to a carbonyl
carbon atom, are very reactive. In some instances, monomer 112
includes pure methyl methacrylate (MMA) such that when emulsified
within mixture 120, it preferably has a droplet size ranging
between 10 and 200 Microns. Inhibitor 114 stabilizes fluid mixture
120 and prevents monomer 112 from premature polymerization. As the
temperature of fluid mixture 120 increases, inhibitor 114 scavenges
free radicals, formed from decomposing peroxides, which may
otherwise react with the double bonds found in the vinyl groups of
monomer 112. The concentration of inhibitor 114 is dependent on the
inherent instability of monomer 112, the pressure and thermal
conditions that the fluid mixture 120 is expected to be exposed to,
and the timeframe in which the fluid mixture 120 is set to be
encapsulated. Inhibitor 114 can be comprised of any solution that
will prevent premature polymerization of monomer 112.
[0078] The specific composition of first mixture 120 is dependent
on the characteristics of localized volume 130 to which the first
mixture 120 is being prepared for. In general, the first mixture
120 will contain sufficient monomer 112, such that an increased
temperature of the first mixture 120 generates a decreased specific
volume of the first mixture 120 assuming inhibitor 114 is not
present. It is to be understood that when the first mixture 120 is
subjected to increased temperatures, as little as a 25.degree. F.
rise, from the ambient conditions in the first location 100, a
decrease in specific volume of the first mixture 120 may occur
assuming inhibitor 114 is not present. The quantity of monomer 112
needed to be considered sufficient, depends on the desired
reduction in specific volume of first mixture 120, which may be
determined by a number of factors. In one embodiment, the localized
volume 130 is an annular volume within a wellbore and the desired
reduction in specific volume of first mixture 120 is determined by
well specific factors, such as well depth and location, the casing
string assembly load limitations, localized temperatures and
pressures within the well system during drilling and completions,
and temperatures and pressures expected within the well system
during production. Generally, it is desired that first mixture 120
includes sufficient monomer such that a decrease in specific volume
of the first mixture 120 corresponds directly to an expected
pressure increase of annular volume if an incompressible fluid were
present.
[0079] Once first mixture 120 is formulated it is transported from
first location 100 to second location 102. Generally first location
100 is remote from second location 102. Second location 102 may be
land-based or aquatic-based and generally is nearby and has access
to localized volume 130. If the second location 102 is land-based
the first mixture 120 may be shipped via one or more of truck,
railway, and air transport from first location 100. If second
location 102 is aquatic-based, first mixture may be shipped via one
or more of truck, railway, and air transport to a marine port where
it is then transported the remaining distance to location 102 via
ship.
[0080] At second location 102, initiator 118 is optionally combined
with first mixture 120 to produce second mixture 122. Initiator 118
is a chemical compound that initiates a chemical chain reaction
within first mixture 120. Initiator 118 counteracts inhibitor 114
such that when second mixture 122 is exposed to elevated
temperatures, second mixture 122 may decrease in specific volume
due to the presence of monomer 112. The quantity of initiator 118
added to first mixture 120 to produce mixture 122 is dependent on
characteristics of localized volume 130 and on the composition of
first mixture 120. Generally sufficient initiator 118 is added
during production of mixture 122 to nullify the influence of
inhibitor 114, therefore allowing second mixture 122 to decrease in
specific volume due to the presence of monomer 112 when exposed to
elevated temperatures. In some instances, enough initiator 118 is
added such that it not only nullifies the influence of inhibitor
114, but also promotes and sustains an acceptable polymerization
rate of monomer 112 within second mixture 122. In certain
embodiments, initiator 118 is considered a free radical initiator
such that it provides sufficient free radicals to mixture 122
needed to completely react inhibitor 114. Additionally initiator
118 may contain the initial free radical required for propagating
polymerization of monomer 112. In certain embodiments, initiator
118 is selected from one or more of a group consisting of
azo-compounds, organic peroxides, and inorganic peroxides.
[0081] According to the present invention, second mixture 122 is
delivered to localized volume 130. Delivery of the second mixture
may generally occur according to any manner known in the art. For
example, wherein the localized volume 130 comprises an annular
volume within a wellbore as shown in FIG. 1, delivery of second
mixture 122 typically occurs in accordance with two generally used
methods: (1) second mixture 122 may be introduced to wellbore
volume 16 through wellbore opening 54 and pumped downward until
reaching wellbore terminus 14, at which point it passes through gap
18 below casing string end 36 of casing string 28 into the annular
volume 50. (2) second mixture 122 is pumped down directly from the
top of annular volume 50 through opening 52 defined by the exterior
of casing string 28 and the interior of casing string 26. The
amount of second mixture 122 delivered to localized volume 130 may
also vary depending on its composition and the characteristics of
localized volume 130. Again, wherein the localized volume 130
comprises an annular volume within a wellbore, the following
factors may be used in determining the quantity of second mixture
122 delivered to the annular volume: well depth and location, the
casing string assembly load limitations, localized temperatures and
pressures within the well system during drilling and completions,
and temperatures and pressures expected within the well system
during production. For instance, second mixture 122 may be prepared
knowing what would have been the expected pressure increase within
the annular volume if an incompressible fluid were present and
therefore, is mixed such that when encapsulated, the expected
decrease in specific volume of the second mixture 122 generally
produces an isobaric environment within the annular volume
regardless of being subject to elevated temperatures.
[0082] FIG. 4 illustrates a flow process of the present invention
for production and delivery of a second mixture 122 to localized
volume 130 while ensuring sufficient monomer 112 and inhibitor 114
are contained within the second mixture 122 prior to delivery.
Similar to FIG. 3, first mixture 120 is prepared from solvent 110,
monomer 112, and inhibitor 114 at first location 100 and is then
transferred to second location 102. At second location 102, first
mixture 120 is analyzed to determine whether it contains a
sufficient amount of monomer 112 and a sufficient amount of
inhibitor 114. Analysis can be performed using any suitable
analytical method to determine the concentration of monomer 112
and/or inhibitor 114 within the first mixture 120." See, for
instance, "Method of Analysis of Polymerizable Monomeric Species in
a Complex Mixture", USPTO application Ser. No. 11/998,331, filed
Nov. 28, 2007.
[0083] If first mixture 120 is found to be lacking sufficient
monomer 112, additional monomer 112 is added at second location 102
and first mixture 120 may be reanalyzed if desired for assurance of
sufficient monomer 112. Similarly, if first mixture 120 is found to
be lacking sufficient inhibitor 114, additional inhibitor 114 is
added at second location 102 and first mixture 120 may be
reanalyzed if desired for assurance of sufficient inhibitor 114.
First mixture 120, with sufficient amounts of monomer 112 and
inhibitor 114, is then optionally mixed with initiator 118 to form
second mixture 122, at which point second mixture 122 is delivered
to localized volume 130. Alternatively, initiator 118 may be added
to first mixture 120 upon arrival to second location 102, thus
forming second mixture 122, and second mixture 122 could be
analyzed to ensure sufficient quantities of monomer 112 and
inhibitor 114 instead of first mixture 120. Similarly, additional
monomer 112 or inhibitor 114 may be added to second mixture 122 to
ensure sufficient quantities prior to delivery of second mixture
122 to localized volume 130.
[0084] FIG. 5 illustrates a flow process of the present invention
for production and delivery of second mixture 122 including a
weighting agent 116 to localized volume 130. Similar to FIG. 3,
first mixture 120 is prepared utilizing solvent 110, monomer 112,
and inhibitor 114 at first location 100 and is then transferred to
second location 102, where it is the optionally mixed with
initiator 118 to form second mixture 122, at which point second
mixture 122 is delivered to localized volume 130. However, in this
process weighting agent 116 is added to either the first mixture
and/or the second mixture 122 prior to delivery to localized volume
130. As shown in FIG. 5 by a segmented dashed and dotted line,
weighting agent 116 may be added to first mixture 120 at either
first location 100 or at second location 102. Likewise, weighting
agent 116 may be added to second mixture 122 just prior to delivery
of second mixture 122 to localized volume 130. It shall be
understood that weighting agent need not be added at all these
mentioned locations and instead may be added at one or a
combination of these locations such that prior to delivery to
localized volume 130 a concentration of weighting agent is present
within second mixture 122. Weighting agent 116 typically is
composed of finely ground solid material offering a high specific
gravity (generally about 3 to 5 grams per cubic centimeter), but
may be any solute that increases the density of first mixture 120
or second mixture 122. Weighting agent 116 is often needed,
especially when the localized volume 130 is at extreme depths below
the surface. For instance, in a deep water well, use of weighting
agent 116 becomes increasingly important as the pressure increases
within the wellbore with deeper depths. In some instances, barite,
which is a mineral that consists of barium sulfate, is used as a
weighting agent 116. Other examples of weighting agents 116 that
may be solely used or used in combination include brines, hematite,
calcium carbonate, siderite, and ilmenite.
[0085] FIG. 6 illustrates a flow process of the present invention
combining the flow processes of FIGS. 4 and 5. First mixture 120 is
prepared utilizing solvent 110, monomer 112, and inhibitor 114, and
possibly weighting agent 116 at first location 100 and is then
transferred to second location 102. At second location 102, first
mixture 120 is analyzed to ensure sufficient amounts of monomer 112
and inhibitor 114. Monomer 112 and/or inhibitor 114 is added as
needed to ensure sufficient quantities of each. First mixture 120
is then optionally mixed with initiator 118 and possibly weighting
agent 116 to form second mixture 122, at which point second mixture
122, possibly mixed with weighting agent 116, is delivered to
localized volume 130.
[0086] While the present invention has been shown in only some of
its forms, those skilled in the art will appreciate that the above
described embodiments are merely illustrative of the present
invention and that many variations of the foregoing described
embodiments can be devised without departing from the spirit and
scope of the invention. For instance, solvent 110 and inhibitor 114
could be mixed at a first location and monomer 112 could later be
mixed in another subsequent location to form first mixture 120. It
is therefore intended that such departures from the present
disclosure, that come within the known customary practice in the
art to which this invention pertains, be included within the scope
of the following appended claims and their equivalents.
[0087] Although the method and process described herein has been
described in connection with preferred embodiments thereof, it will
be appreciated by those skilled in the art that additions,
deletions, modifications, and substitutions not specifically
described may be made without departing from the spirit and scope
of the method and process as defined in the appended claims.
* * * * *